JP7022140B2 - Precooling of natural gas by high pressure compression and expansion - Google Patents

Description

[Cross-reference to related applications]
This application is in US Patent Application No. 62 / 458,127 entitled "Precooling Natural Gas by High Pressure Compression and Expansion" filed February 13, 2017, which is incorporated herein by reference in its entirety. It claims priority interests.

This application has a common inventor and transferee whose disclosure is incorporated herein by reference in its entirety and precools the "natural gas feed stream" of the application on the same date as the specification. It relates to US Provisional Patent Application No. 62 / 458, 131, entitled "Increased Efficiency in LNG Generation Systems".

The present invention relates to the liquefaction of natural gas to form liquefied natural gas (LNG), more specifically when the construction and / or maintenance of major facilities and / or the environmental impact of conventional LNG plants is harmful. Concerning the generation of LNG in certain remote or sensitive areas.

LNG production is a fast-growing means of supplying natural gas from locations with abundant supplies of natural gas to distant locations with strong demand for natural gas. Traditional LNG generation cycles can include a) initial treatment of natural gas resources to remove contaminants such as water, sulfur compounds, and carbon dioxide, and b) self-freezing, external freezing, dilute oil, and more. Separation of some heavy hydrocarbon gases such as propane, butane, pentane, etc., and c) liquefied natural gas at about -160 ° C at near atmospheric pressure, which is substantially natural by external freezing. Refrigeration of gas and d) transportation of LNG products to market locations on ships or tankers designed for this purpose, and e) regassing to pressurized natural gas that can be distributed to natural gas consumers. Includes repressurization and regasification of LNG in the conversion plant. The stage (c) of the conventional LNG cycle usually requires the use of a large refrigerating compressor, often powered by a large gas turbine driver that emits significant carbon and other emissions. Large capital investment of billions of US dollars and extensive infrastructure are needed as part of the liquefaction plant. Conventionally, the stage (e) of the LNG cycle is the stage of repressurizing the LNG to the required pressure using a low temperature pump, and then passing through the intermediate fluid but finally by exchanging heat with seawater, or the LNG. It generally comprises the step of regasifying LNG into pressurized natural gas by burning a portion of the natural gas to heat and evaporate.

Although LNG production is generally known, technological improvements can still provide LNG producers with a significant opportunity to increase efficiency and extend LNG production to additional geographic areas. For example, floating LNG (FLNG) is a relatively new technical option for producing LNG. This technique involves the construction of gas treatment and liquefaction facilities on floating structures such as barges or ships. FLNG is a technical solution for monetizing offshore gas that is not economically feasible to build a gas pipeline to the coast. FLNG is also increasingly considered for terrestrial and coastal gas fields located in remote environmentally sensitive and / or politically difficult areas. This technique has certain advantages over traditional onshore LNG in that it has a reduced environmental footprint at the production site. The technology can also accomplish projects faster and at lower cost, as the majority of LNG facilities are built in shipyards with lower wage rates and reduced execution risk.

FLNG has several advantages over traditional onshore LNG, but significant technical challenges remain in the application of this technique. For example, FLNG structures must provide the same level of gas treatment and liquefaction for areas or spaces that are often less than a quarter of what is considered available for onshore LNG plants. For this reason, there is a need to develop technologies that reduce the footprint of liquefaction facilities while maintaining their capacity, thereby reducing overall project costs. Several liquefaction techniques have been proposed for use in FLNG projects. Leading techniques include a single mixed refrigerant (SMR) step, a double mixed refrigerant (DMR) step, and an expander-based (or expanded) step.

In contrast to the DMR process, the SMR process has the advantage of allowing all equipment and bulk associated with the complete liquefaction process to fit into a single FLNG module. The SMR liquefaction module is placed on the upper deck of the FLNG structure as a complete SMR train. This "LNG in box" concept is preferred for FLNG project execution as it allows inspection and commissioning of SMR trains at locations different from where the FLNG structure is constructed. It can also enable labor cost savings as it reduces working hours at shipyards, where wage rates tend to be higher than wage rates in traditional production yards. The SMR process has the additional advantage of being a relatively efficient, simple, and compact freezing process when compared to other mixed refrigerant processes. Moreover, the SMR liquefaction step is typically 15% to 20% more efficient than the inflator-based liquefaction step.

The choice of SMR process for LNG liquefaction in the FLNG project has its advantages, but has some drawbacks for the SMR process. The required use and storage of flammable refrigerants such as propane significantly increases the loss prevention problem with FLNG. The SMR process is also capacity limited, which increases the number of trains required to reach the desired LNG production. For these reasons and others, a significant amount of upper deck space and weight is required for the SMR train. Since the upper deck space and weight significantly increase the FLNG project cost, there remains a need to improve the SMR liquefaction process to further reduce the upper deck space, weight and complexity, thereby improving the project economy. There is.

The inflator-based process has several advantages that make it well suited for FLNG projects. The most significant advantage is that this technique provides liquefaction without the need for external hydrocarbon refrigerants. Eliminating liquid hydrocarbon refrigerant inventories, such as propane storage, significantly reduces safety concerns regarding FLNG projects. An additional advantage of the inflator-based process over the mixed refrigerant process is that the inflator-based process is less sensitive to offshore motion, as the main refrigerant remains largely in the gas phase. However, the application of the inflator-based process to FLNG projects with LNG production higher than 2 million tonnes (MTA) each year has been found to be less attractive than the use of mixed refrigerant processes. The capacity of the train in the inflator-based process is typically less than 1.5 MTA. In contrast, a mixed refrigerant process train, such as that of a known double mixed refrigerant process, can have a train capacity higher than 5 MTA. The size of the inflator-based process train is limited because the refrigerant remains largely vapor throughout the process and the refrigerant absorbs energy through its sensible heat. For these reasons, the refrigerant volume flow rate is large throughout the process, and the size and piping of the heat exchangers are correspondingly larger than those of the mixed refrigerant process. In addition, the limitation of the stretcher horsepower size results in a parallel rotating machine as the capacity of the inflator-based process train increases. The production rate of FLNG projects using an inflator-based process can be higher than 2 MTA if multiple inflator-based trains are allowed. For example, for a 6MTA FLNG project, a parallel expander-based process train of 6 or 7 or more may be sufficient to achieve the required production. However, the number of equipment, complexity, and cost all increase with multiple inflator trains. In addition to this, the assumption of process simplicity of the expander-based process compared to the mixed refrigerant process is that the mixed refrigerant process can obtain the required production rate in one or two trains, but multiple trains. Is beginning to be questioned when is required for inflator-based processes. For these reasons, there is a need to develop a high LNG production capacity FLNG liquefaction process that has the advantages of an inflator-based process. There is yet another need to develop FLNG technology solutions that can better address the challenges that vessel movement has for gas treatment.

U.S. Pat. No. 6,421,302 describes a feed gas inflator-based process in which two independent closed freezing loops are used to cool the feed gas to form an LNG. In an embodiment, the first closed freezing loop uses a feed gas or a feed gas component as the refrigerant. Nitrogen gas is used as a refrigerant for the second closed freezing loop. This technique requires less equipment and upper deck space than a double-loop nitrogen expander-based process. For example, the volumetric flow rate of the refrigerant into the low pressure compressor can be reduced by 20 to 50% for this technique compared to a double loop nitrogen expander based process. However, this technique is still limited to capacities less than 1.5 MTA.

U.S. Pat. No. 8,616,012 describes a feed gas inflator-based process in which the feed gas is used as a refrigerant in a closed freezing loop. Within this closed freezing loop, the refrigerant is compressed to a pressure higher than, or equal to, or more preferably 2,500 psia (17,240 kPa) above 1,500 psia (10,340 kPa). The refrigerant is then cooled and expanded to achieve cryogenic temperatures. This cooled refrigerant is used in the heat exchanger to cool the feed gas from warm temperature to cryogenic temperature. The supercooled cooling loop is then used to further cool the feed gas to form LNG. In one embodiment, the supercooling loop is a closed loop in which flush gas is used as the refrigerant. This feed gas inflator-based process has the advantage of not being limited to a train capacity range of less than 1 MTA. A train size of about 6 MTA is considered. However, this technique has the drawbacks of high equipment count and increased complexity due to its requirements for the two independent freezing loops and the compression of the feed gas. In addition, high pressure operation also means that the equipment and piping will be much heavier than those in other inflator-based processes.

GB 2,486,036 is a feed gas inflator-based process that is an open loop refrigeration cycle that includes a precooling inflator loop and a liquefied inflator loop in which the expanded gas phase is used to liquefy natural gas. Explaining. According to this document, the inclusion of a liquefied expander in the process significantly reduces the recycled gas rate and the overall required freezing power. This technique has the advantage of being simpler than other techniques as simply one type of refrigerant is used with a single compression string. However, this technique is still limited to capacities less than 1.5 MTA, which requires the use of non-standard equipment liquefied expanders for LNG production. This technique has also been shown to be less efficient than other techniques in terms of liquefaction of dilute natural gas.

U.S. Pat. No. 7,386,996 describes an inflator-based process in which the precooling and freezing process precedes a main inflator-based cooling circuit. The pre-cooling and freezing process involves a carbon dioxide freezing circuit in a cascade arrangement. The carbon dioxide refrigeration circuit has three pressure levels: a high pressure level that provides warm end cooling, a medium pressure level that provides intermediate temperature cooling, and a low pressure level that provides cold end cooling for the carbon dioxide refrigeration circuit. It is possible to cool the feed gas and the refrigerant gas of the main inflator-based cooling circuit. This technique is more efficient and has a higher production capacity than an inflator-based process that lacks a precooling step. This technique has additional advantages for FLNG applications as the precooling and refrigerating cycle uses carbon dioxide as the refrigerant instead of the hydrocarbon refrigerant. However, carbon dioxide refrigeration circuits come at the expense of additional complexity to the liquefaction process, as additional refrigerant and a substantial amount of extra equipment are introduced. For FLNG applications, the carbon dioxide refrigeration circuit is within its own module and can be sized to provide precooling for multiple inflator-based processes. This arrangement has the drawback of requiring a significant amount of pipe connection between the precooling module and the main inflator-based module. The "LNG in box" advantage discussed above is no longer realized.

US Provisional Patent Application No. 62 / 458,131 U.S. Pat. No. 6,421,302 U.S. Pat. No. 8,616,012 GB 2,486,036 U.S. Pat. No. 7,386,996 U.S. Patent Publication No. 2017/0167788 U.S. Patent Publication No. 2017/016775 U.S. Patent Publication No. 2017/016777 U.S. Patent Publication No. 2017/0167786

That is, there remains a need to develop a precooling process that does not require additional refrigerant and does not introduce a significant amount of extra equipment into the LNG liquefaction process. There is an additional need to develop a precooling process that can be placed in the same module as the liquefaction module. Such precooling steps, along with SMR steps or inflator-based steps, are considered to be particularly suitable for FLNG applications where upper deck space and weight have a significant impact on project economics. There remains a specific need to develop an LNG production process that has the advantages of an inflator-based process and, in addition, has a high LNG production capacity without significantly increasing the facility footprint. There is yet another need to develop LNG technology solutions that can better address the challenges that vessel movement has for gas treatment. Such a high capacity inflator-based liquefaction process is considered to be particularly suitable for FLNG applications where the inherent safety and simplicity of the inflator-based liquefaction process is highly valued.

The present invention provides a method for producing liquefied natural gas (LNG). Natural gas streams are sourced from natural gas supplies. The natural gas stream can be compressed in at least two series-arranged compressors up to a pressure of at least 2,000 psia to form a compressed natural gas stream. The compressed natural gas stream can be cooled by indirect heat exchange with ambient temperature air or water to form a cooled compressed natural gas stream. The cooled compressed natural gas stream can be additionally cooled to a temperature lower than the ambient temperature to form an additional cooled compressed natural gas stream. The additional cooling compressed natural gas stream is in at least one work-producing natural gas expander up to a pressure of less than 3,000 psia and not higher than the pressure at which at least two series-arranged compressors compress the natural gas stream. It can be inflated, thereby forming a cold natural gas stream. The cold natural gas stream can then be liquefied by indirect heat exchange with the refrigerant to form the liquefied natural gas and the warm refrigerant. The cooled compressed natural gas stream is additionally cooled using a warm refrigerant.

The present invention also provides an apparatus for liquefaction of natural gas. At least two series of compressors compress the natural gas stream to a pressure higher than 2,000 psia, thereby forming a compressed natural gas stream. The cooling element cools the compressed natural gas stream to form a cooled compressed natural gas stream. The heat exchanger further cools the cooled compressed natural gas stream to a temperature below the ambient temperature, thereby producing an additional cooled compressed natural gas stream. At least one work-generating inflator expands the additional cooling compressed natural gas stream to a pressure less than 3,000 psia and not higher than the pressure at which at least two series-arranged compressors compress the natural gas stream. It forms a cold natural gas stream. A liquefaction train liquefies a chilled natural gas stream. The warm refrigerant used by the liquefaction train is directed at the heat exchanger to further cool the cooling compressed natural gas stream.

The present invention further provides a floating LNG structure. At least two series of compressors compress the natural gas stream to a pressure higher than 2,000 psia, thereby forming a compressed natural gas stream. The cooling element cools the compressed natural gas stream to form a cooled compressed natural gas stream. The heat exchanger further cools the cooled compressed natural gas stream to a temperature below the ambient temperature, thereby producing an additional cooled compressed natural gas stream. At least one work-generating inflator expands the additional cooling compressed natural gas stream to a pressure less than 3,000 psia and not higher than the pressure at which at least two series-arranged compressors compress the natural gas stream. It forms a cold natural gas stream. A liquefaction train liquefies a chilled natural gas stream. The warm refrigerant used by the liquefaction train is directed at the heat exchanger to further cool the cooling compressed natural gas stream.

FIG. 6 is a schematic representation of a high pressure compression and expansion (HPCE) module according to the disclosed embodiments. FIG. 6 is a graph showing heating and cooling curves for an inflator-based freezing process. It is a schematic diagram which shows the arrangement of the single mixed refrigerant (SMR) liquefaction module by a known principle. It is a schematic diagram which shows the arrangement of the SMR liquefaction module by the aspect to be disclosed. It is a schematic diagram of the HPCE module according to the disclosed aspect. It is a schematic diagram of the HPCE module and the feed gas inflator-based liquefaction module according to the disclosed aspect. It is a flow chart of the method of forming LNG by liquefying natural gas according to the disclosed aspect. FIG. 6 is a schematic representation of a high pressure compression and expansion (HPCE) module according to the disclosed embodiments. It is a schematic diagram of the HPCE module and the feed gas inflator-based liquefaction module according to the disclosed aspect. It is a schematic diagram of the HPCE module and the feed gas inflator-based liquefaction module according to the disclosed aspect. It is a schematic diagram of the HPCE module and the feed gas inflator-based liquefaction module according to the disclosed aspect. It is a flow chart of the method of forming LNG by liquefying natural gas according to the disclosed aspect.

Various specific embodiments, embodiments, and versions, including the definitions adopted herein, are described herein below. Those skilled in the art will appreciate that such embodiments, embodiments and versions are merely exemplary and that the invention can be practiced in other ways. Any reference to the "invention" may refer to one or more of embodiments defined by the claims, but not all. The use of the title is for convenience only and does not limit the scope of the invention. For the purposes of clarity and simplification, similar reference numbers in some figures represent similar items, stages, or structures and are not described in detail in any of the figures.

All numerical values in the detailed description and claims of the present specification are modified by the display value of "about" or "almost", and take into account experimental errors and variations that will be expected by those skilled in the art. ..

As used herein, the term "compressor" means a machine that increases the pressure of a gas by applying work. A "compressor" or "freezing compressor" includes any unit, device, or device capable of increasing the pressure of a gas stream. This includes a compressor with a single compression step or stage, or a compressor with multi-stage compression or stages, or particularly a multi-stage compressor in a single casing or shell. The compressed evaporated stream can be provided to the compressor at various pressures. Several stages or stages of the cooling process may involve two or three or more compressors in parallel, in series, or both. The invention is not particularly limited by the type or arrangement or layout of one or more compressors in any refrigeration cycle.

As used herein, "cooling" broadly refers to lowering and / or reducing the temperature and / or internal energy of a substance by any suitable, desirable, or required amount. Cooling is at least about 1 ° C, at least about 5 ° C, at least about 10 ° C, at least about 15 ° C, at least about 25 ° C, at least about 35 ° C, or at least about 50 ° C, or at least about 75 ° C, or at least about 85 ° C. , Or at least about 95 ° C, or at least about 100 ° C. Cooling can use any suitable heat sink such as steam generator, hot water heating, cooling water, air, refrigerant, other processing streams (integration), and combinations thereof. One or more sources of cooling can be combined and / or cascaded to reach the desired outlet temperature. The cooling stage can use a cooling unit equipped with any suitable device and / or equipment. Depending on some embodiments, cooling can include indirect heat exchange with one or more heat exchangers and the like. In an alternative form, cooling can use evaporation (heat of vaporization) cooling and / or direct heat exchange such as spraying the liquid directly into the processing stream.

As used herein, the term "expansion device" is suitable for reducing the pressure of a row of fluids (eg, a liquid stream, a vapor stream, or a polyphase stream containing both liquid and vapor). Refers to one or more devices. Unless specifically defining a particular type of inflatable device, the inflatable device may be (1) at least partially by isentropic means, or (2) at least partially by isentropic means. Or it can be a combination of both (3) isentropic means and isentropic means. Suitable devices for enthalpy expansion of natural gas are known in the art and are generally not limited to, for example, valves, control valves, "Joule-Thomson (JT)" valves, or Venturi. Includes manual or self-actuated throttle devices such as devices. Suitable devices for isentropic expansion of natural gas are known in the art and generally include equipment such as expanders or turbo expanders that extract or drive work from such expansions. Suitable devices for isentropic expansion of liquid streams are known in the art and are generally of the inflator, hydraulic inflator, liquid turbine, or turbo inflator that extracts or drives work from such expansion. Including equipment such as. Examples of combinations of both isentropic and isoenthalpy means can be parallel "Joule-Thomson" valves and turbo expanders, which can be used alone or with JT valves and turbo expansion. Provides the ability to use both vessels at the same time. Equal enthalpy or isotropic expansion can be performed on all liquid phases, all steam phases, or mixed phases, from a steam stream or liquid stream to a polyphase stream (a stream having both steam and liquid phases), or. It can be done to facilitate a phase change to a single phase stream different from its initial phase. In the description of the drawings herein, reference to more than one inflatable device in every drawing does not necessarily mean that each inflatable device is of the same type or size.

The term "gas" is used synonymously with "vapor" and is defined as a substance or mixture of substances in a gaseous state to distinguish it from a liquid or solid state. Similarly, the term "liquid" means a substance or mixture of substances in a liquid state to distinguish it from a gas or solid state.

"Heat exchanger" broadly means any device capable of transferring thermal or cold energy from one medium to another, such as between at least two different fluids. Heat exchangers include "direct heat exchange" and "indirect heat exchange". Therefore, the heat exchangers are parallel or countercurrent heat exchangers, indirect heat exchangers (eg, spiral wound heat exchangers or plate fin heat exchangers such as brazed aluminum plate fin types), direct contact heat exchangers. , Shell and tube heat exchanger, spiral, hairpin, core, core and kettle, printed circuit, double pipe, or any other type of known heat exchanger. can. A "heat exchanger" also allows the passage of one or more streams through it, affecting direct or indirect heat exchange between one or more lines of refrigerant and one or more feed streams. It may refer to any column, tower, unit, or other arrangement that is intended to exert.

As used herein, the term "indirect heat exchange" means to bring two fluids into a heat exchange relationship without any physical contact or mixing of the fluids with each other. Core inkettle heat exchangers and brazed aluminum plate fin heat exchangers are examples of equipment that facilitates indirect heat exchange.

As used herein, the term "natural gas" refers to a multi-component gas obtained from a crude oil field (accompanying gas) or from an underground gas-bearing formation (non-accompanying gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C ₁ ) as a significant component. Natural gas streams may also contain ethane (C ₂ ), higher molecular weight hydrocarbons, and one or more acid gases. Natural gas may also contain small amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil.

Certain embodiments and features are described using a set of numerical upper bounds and a set of numerical lower bounds. It must be acknowledged that the range from any lower limit to any upper limit is considered unless otherwise instructed. All numbers are displayed as "about" or "almost" and take into account experimental errors and variations that would be expected by those of skill in the art.

All patents, test procedures, and other documents cited in this application are fully incorporated by citation to the extent that such disclosure does not contradict this application and all jurisdictions that allow such incorporation.

The embodiments disclosed herein describe a step of precooling natural gas to a liquefaction step for the production of LNG by adding high pressure compression and high pressure expansion steps to the feed gas. More specifically, the present invention describes a process in which the pretreated natural gas is compressed to a pressure higher than 2,000 psia (13,790 kPa) or more preferably higher than 3,000 psia (20,680 kPa). .. The high temperature compressed gas is cooled by exchanging heat with the environment to form a compressed pretreatment gas. The cooling compressed gas is additionally cooled to a temperature lower than the ambient temperature to form an additional cooling compression pretreatment gas stream. The additional cooling compression pretreatment gas stream is a pretreatment gas that has been expanded and cooled in a nearly isoentropically to a pressure of less than 3,000 psia (20,680 kPa) or more preferably to a pressure of less than 2,000 psia (13,790 kPa). The pressure of the pretreatment gas cooled here is less than the pressure of the compressed pretreatment gas. The cold pretreatment gas can be directed to one or more SMR liquefaction trains, or the cold pretreatment gas is one or more expander-based liquefaction trains where the gas is further cooled to form an LNG. Can be turned to. Aspects described herein are the following patent applications: US Patent Publication No. 2017/0167788, entitled "Methods and Systems for Separating Nitrogen from Liquefied Natural Gas Using Liquefied Natural Gas", "Liquid Nitrogen". US Patent Publication No. 2017/016775 entitled "Expansion-based LNG Production Process Enhanced with Related to and / or further to one or more of Japanese Patent Publication No. 2017/01677787 and US Patent Publication No. 2017/0167786 entitled "Precooling Natural Gas by High Pressure Compression and Expansion". Explained, all filed on November 10, 2016 with a common concessionaire, the disclosures of these patents are incorporated herein by reference in their entirety.

FIG. 1 is a diagram illustrating an embodiment of a precooling step. The precooling step is referred to herein as high pressure compression and expansion (HPCE) step 100. The HPCE step 100 can include a first compressor 102 that compresses the pretreated natural gas stream 104 to form an intermediate pressure gas stream 106. The intermediate pressure gas stream 106 can flow through a first heat exchanger 108 that is cooled by the intermediate pressure gas stream 106 indirectly exchanging heat with the environment to form a cooling intermediate pressure gas stream 110. The first heat exchanger 108 can be an air-cooled heat exchanger or a water-cooled heat exchanger. Next, the cooling intermediate pressure gas stream 110 can be compressed in the second compressor 112 to form the high pressure gas stream 114. The pressure of the high pressure gas stream 114 can be higher than 2,000 psia (13,790 kPa) or more preferably higher than 3,000 psia (20,680 kPa). The high-pressure gas stream 114 can flow through a second heat exchanger 116 that is cooled by the high-pressure gas stream 114 indirectly exchanging heat with the environment to form the cooled high-pressure gas stream 118. The second heat exchanger 116 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooling high pressure gas stream 118 can then form the pretreated gas stream 122 that has been expanded and cooled in the inflator 130. The pressure of the cold pretreatment gas stream 122 can be less than 3,000 psia (20,680 kPa), or more preferably less than 2,000 psia (13,790 kPa), and the pressure of the cold pretreatment gas stream 122 can be less than 3,000 psia (20,680 kPa). , Less than the pressure of the cooling high pressure gas stream 118. In a preferred embodiment, the second compressor 112 can be driven exclusively by the shaft power generated by the inflator 120, as shown by the dashed line 124.

In aspects, the SMR liquefaction step can be enhanced by the addition of an HPCE step upstream of the SMR liquefaction step. More specifically, in this embodiment, the pretreated natural gas can be compressed to a pressure higher than 2,000 psia (13,790 kPa) or more preferably higher than 3,000 psia (20,680 kPa). The high temperature compressed gas is then cooled by heat exchange with the environment to form a compression pretreatment gas. Next, the compression pretreatment gas is a pretreatment gas that has been expanded and cooled in a substantially isoentropically to a pressure of less than 3,000 psia (20,680 kPa) or more preferably to a pressure of less than 2,000 psia (13,790 kPa). The pressure of the pretreatment gas cooled here is less than the pressure of the compressed pretreatment gas. The chilled pretreatment gas is then directed to a plurality of SMR liquefaction trains in which the chilled pretreatment gas is further cooled to form LNG.

The combination of the SMR train and the HPCE process has several advantages over the conventional SMR process in which the pretreated natural gas is sent directly to the SMR liquefaction train. For example, precooling of natural gas using the HPCE process allows an increase in LNG production rate in the SMR train for a given horsepower in the SMR train. As mentioned above in connection with FIGS. 3 and 4, the SMR trains powered by gas turbines, each with an output of approximately 50 MW (MW), are each one out of five trains producing LNG at 1.5 MTA each. It can be reduced to 4 trains with increased capacity of 0.9 MTA. For this given example, the HPCE module substantially replaces one of the SMR modules. Replacing one SMR module with an HPCE module is advantageous because it is expected that the HPCE module will be smaller, lighter, and cost significantly less than the SMR module. Like the SMR module, the HPCE module can have a gas turbine of comparable size to provide compression power, which will also have an equivalent amount of air or water chiller. However, unlike SMR modules, HPCE modules do not have expensive main low temperature heat exchangers. Containers and pipes associated with the refrigerant flow in the SMR module are removed in the HPCE module. Moreover, the HPCE module does not have expensive cold pipes and all fluid streams remain single phase within the HPCE module.

Another advantage is that the number of SMR trains is reduced by one, which reduces the required storage of refrigerant. Similarly, since most of the warm temperature cooling of the gas occurs in the HPCE module, the heavy hydrocarbon component of the mixed refrigerant can be reduced. For example, the propane component of the mixed refrigerant can be removed with little loss of efficiency in the SMR process.

Another advantage is that for the SMR process, which accepts the cold pretreatment gas from the HPCE process, the volumetric flow rate of the evaporative refrigerant in the SMR process is more than 25% less than that of the conventional SMR process, which accepts the warm pretreatment gas. That's what it means. The lower volume flow of the refrigerant can reduce the size of the main cold heat exchanger and the size of the low pressure mixed refrigerant compressor. The lower volumetric flow rate of the refrigerant is due to its higher vapor pressure compared to that of the conventional SMR process.

The known propane precooled mixed refrigerant step and double mixed refrigerant (DMR) step can be considered as a version of the SMR step in combination with the precooled refrigeration circuit, but between such steps and aspects of the present disclosure. There is a significant difference. For example, a known step uses a cascade propane refrigeration circuit or a warm-end mixed refrigerant to precool the gas. Both of these known steps have the advantage of providing 5% to 15% higher efficiency than the SMR step. Moreover, the capacity of a single liquefaction train using these known steps can be significantly larger than that of a single SMR train. However, the precooling and refrigerating circuits of these techniques come at the expense of additional complexity to the liquefaction process due to the introduction of additional refrigerant and significant amounts of extra equipment. For example, the disadvantages of higher complexity and weight of DMR may outweigh the higher efficiency and capacity when deciding on one, and its advantages of DMR and SMR processes for FLNG applications. The known process considers the addition of a precooling process upstream of the SMR process, driven primarily by the need for higher thermal efficiency and higher LNG production capacity for a single train. The HPCE process combined with the SMR process has not been previously realized as it does not provide the higher thermal efficiency provided by the refrigerant-based precooling process. As mentioned above, the thermal efficiency of the HPCE process having SMR is almost the same as that of the stand-alone SMR process. The disclosed embodiment is a description of a precooling process that aims to reduce the weight and complexity of the liquefaction process rather than enhancing thermal efficiency, which was traditionally the greatest driving force for the addition of a precooling process for onshore LNG applications. Is considered to be new, at least in part. For newer uses of FLNG, the footprint, weight, and complexity of the liquefaction process can be a driving force that outweighs the project cost. Therefore, the disclosed aspects are of particular value.

In aspects, the inflator-based liquefaction step can be enhanced by the addition of an HPCE step upstream of the inflator-based step. More specifically, in this embodiment, the pretreated natural gas stream can be compressed to a pressure higher than 2,000 psia (13,790 kPa) or more preferably higher than 3,000 psia (20,680 kPa). .. The high temperature compressed gas can then be cooled by heat exchange with the environment to form a compressed pretreatment gas. The compressed pretreatment gas forms a cold pretreatment gas that is expanded almost isoentropically to a pressure of less than 3,000 psia (20,680 kPa) or more preferably to a pressure of less than 2,000 psia (13,790 kPa). The pressure of the pretreated gas cooled here can be less than the pressure of the compressed pretreated gas. The cooled pretreatment gas is directed to an expander-based process in which the gas is further cooled to form LNG. In a preferred embodiment, the chilled pretreatment gas can be directed to a feed gas inflator-based process.

FIG. 2 shows a typical temperature cooling curve 200 for an inflator-based liquefaction process. The higher temperature curve 202 is the temperature curve for the natural gas stream. The lower temperature curve 204 is a composite temperature curve of a cold cooling stream and a warm cooling stream. As shown, the cooling curve is marked by three temperature pinch points 206, 208, and 210. Each pinch point is a location within the heat exchanger where the combined heat capacity of the cooling stream is less than that of the natural gas stream. This imbalance in heat capacity between streams results in a reduction in the temperature difference between the cooling streams against the minimum allowable temperature difference that provides an effective heat transfer coefficient. The lowest temperature pinch point 206 occurs where the colder of the two cooling streams, typically the cold cooling stream, enters the heat exchanger. The intermediate temperature pinch point 208 occurs where a second cooling stream, typically a warm cooling stream, enters the heat exchanger. A warm temperature pinch point 210 occurs where cold and warm cooling streams exit the heat exchanger. The warm temperature pinch point 210 subsequently raises the need for a higher mass flow rate for a warmer cooling stream that can increase the power demand of the inflator-based process.

One proposed method of removing the hot temperature pinch point 210 is to precool the feed gas with an external refrigeration system such as a propane cooling system or a carbon dioxide cooling system. For example, US Pat. No. 7,386,966 removes a warm temperature pinch point by using a precooling and freezing process that includes a carbon dioxide freezing circuit in a cascade arrangement. This external pre-cooling and freezing system has the disadvantage of significantly increasing the complexity of the liquefaction process as additional refrigerant systems are introduced despite the equipment associated with it. Aspects disclosed herein are to compress the feed gas to a pressure higher than 2,000 psia (12,790 kPa), cool the compressed feed gas stream, and compress the compressed gas stream to 3,000 psia (20,690 kPa). ) Reduces the effects of warm temperature pinch points 210 by precooling the feed gas stream by expanding to a pressure below, where the expansion pressure of the feed gas stream is less than the compression pressure of the feed gas stream. be. The process of cooling the feed gas stream results in a significant reduction in the required mass flow rate of the inflator-based process cooling system. It also improves the thermodynamic efficiency of the inflator-based process without significantly increasing the number of instruments and without the addition of external freezing.

In a preferred embodiment, the inflator-based process can be a feed gas inflator-based process. The feed gas inflator-based process can be an open loop feed gas step in which the recirculation loop includes a warm end inflator loop and a cold end inflator loop. The warm-end inflator can emit a first cooling stream and the cold-end inflator can emit a second cooling stream. The temperature of the first cooling stream is higher than the temperature of the second cooling stream. In the embodiment, the pressure of the first cooling stream is higher than the pressure of the second cooling stream. In another aspect, the cold end expander emits a two-phase stream separated into a second cooling stream and a second pressurized LNG stream. Specifically, it allows the generated natural gas stream to be treated and, if present, impurities such as water, heavy hydrocarbons, and acid gas to be removed to make the natural gas suitable for liquefaction. be able to. The treated natural gas can be directed to the HPCE process where it is compressed to a pressure higher than 2,000 psia (12,790 kPa) or higher than 3,000 psia (20,680 kPa). The high temperature compressed gas can then be cooled by heat exchange with the environment to form compressed natural gas. The compressed natural gas is expanded almost equienotropically to a pressure of less than 3,000 psia (20,680 kPa) or more preferably to a pressure of less than 2,000 psia (12,790 kPa) to form a cooled pretreatment gas stream. The pressure of the treated gas cooled here is less than the pressure of the compressed natural gas. The chilled treated natural gas can be completely liquefied by direct heat exchange with the first cooling stream and the second cooling stream to produce a first pressurized LNG stream. The first pressurized LNG stream can be mixed with the second pressurized LNG stream to form a pressurized LNG stream. The pressurized LNG stream can be directed to at least one two-phase separation stage in which the two-phase stream obtained by reducing the pressure of the pressurized LNG stream is separated into a flash gas stream and an LNG generation stream. The flash gas stream exchanges heat with the pressurized LNG stream and the cold treated natural gas stream before being compressed to mix with a second cooling stream that is pressurized and / or recirculated for the fuel gas. can do.

The combination of the feed gas inflator-based process and the HPCE process has several advantages over the conventional feed gas inflator-based process. By including the HPCE process at the same time, the effect of the feed gas expander-based process can be enhanced by 20 to 25%. Therefore, the feed gas inflator process of the present invention does not use external freezing and has efficiencies approaching those of the SMR process while still providing the advantages of ease of operation and reduced number of devices. In addition, the refrigerant flow rate and size of the recirculation compressor is expected to be significantly lower compared to the inflator-based process combined with the HPCE process. For these reasons, the production capacity of a single liquefaction train according to the disclosed embodiments may exceed the production capacity of a similarly sized conventional inflator-based liquefaction process by more than 50%.

FIG. 3 is a diagram illustrating the arrangement of the SMR liquefaction module on the FLNG 300. The pretreated or otherwise suitable natural gas 302 can be evenly distributed among the five identical or nearly identical SMR liquefaction modules or trains 304, 306, 308, 310, 312. As an example, each SMR liquefaction module can receive about 50 MW of compression power from either a gas turbine or an electric motor (not shown) to drive the compressor of the SMR liquefaction module. Each SMR liquefaction module can generate about 1.5 MTA of LNG for a total stream daily production of about 7.5 MTA of LNG for FLNG applications.

FIG. 4 is a diagram illustrating the arrangement of the SMR liquefaction module or trains 406, 408, 410, 412 and the HPCE module on the FLNG 400 according to the disclosed embodiment. Natural gas 402 that is pretreated or otherwise suitable for liquefaction can be directed to the HPCE module 404 that produces a cold pretreated gas stream 405. The HPCE module 404 can, for example, receive about 50 MW of compression power from a gas turbine or electric motor (not shown) to drive one or more compressors within the HPCE module 404. The cooled pretreatment gas can be evenly distributed among the four identical or nearly identical SMR liquefaction modules 406, 408, 410, 412. Each SMR liquefaction module can receive about 50 MW of compression power from either a gas turbine or an electric motor (not shown) to drive the compressor of each SMR liquefaction module. Each SMR liquefaction module is capable of producing about 1.9 MTA of LNG for a total stream daily production of about 7.6 MTA of LNG for FLNG applications.

FIG. 5 is a diagram illustrating an embodiment of the HPCE module 500 referred to in FIG. The natural gas stream 502, which has been pretreated to remove impurities or is otherwise suitable for liquefaction, is fed into the first compressor 504 to form the first intermediate pressure gas stream 506. The first intermediate pressure gas stream 506 is a first heat exchange that forms a first intermediate pressure gas stream 510 that has been cooled and cooled by the first intermediate pressure gas stream 506 indirectly exchanging heat with the environment. It can flow through the vessel 508. The first heat exchanger 508 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled first intermediate pressure gas stream 510 can then be compressed in the second compressor 512 to form a second intermediate pressure gas stream 514. The second intermediate pressure gas stream 514 forms a second heat exchange that forms a second intermediate pressure gas stream 518 that has been cooled and cooled by the second intermediate pressure gas stream 514 indirectly exchanging heat with the environment. It can flow through the vessel 516. The second heat exchanger 516 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled second intermediate pressure gas stream 518 can then be compressed in the third compressor 520 to form a high pressure gas stream 522. The pressure of the high pressure gas stream 522 can be higher than 2,000 psia (13,790 kPa) or more preferably higher than 3,000 psia (20,680 kPa). The high-pressure gas stream 522 can flow through a third heat exchanger 524 that is cooled by the high-pressure gas stream 522 indirectly exchanging heat with the environment to form a cooling high-pressure gas stream 526. The third heat exchanger 524 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooling high pressure gas stream 526 can then form a pretreated gas stream 530 that has been expanded and cooled in the inflator 528. The pressure of the cold pretreatment gas stream 530 can be less than 3,000 psia (20,680 kPa) or more preferably less than 2,000 psia (13,790 kPa), and the pressure of the cold pretreatment gas stream 530 is It can be less than the pressure of the cooling high pressure gas stream 526. In aspects, the third compressor 520 can be driven exclusively by the shaft power generated by the inflator 528, as indicated by wire 532.

FIG. 6 is a diagram illustrating an HPCE step 601 combined with a feed gas expander-based LNG liquefaction step 600. Natural gas can be treated and, if present, impurities such as water, heavy hydrocarbons, and acid gas removed to produce a treated natural gas stream 602 suitable for liquefaction. The treated natural gas stream 602 can be mixed with the recirculated refrigerant gas stream 604 to form a composite stream 606. The composite stream 606 can be directed to HPCE step 601 in which the composite stream 606 is compressed in the first compressor 608 to form an intermediate pressure gas stream 610. The intermediate pressure gas stream 610 can flow through a first heat exchanger 612 that is cooled by the intermediate pressure gas stream 610 indirectly exchanging heat with the environment to form a cooling intermediate pressure gas stream 614. The first heat exchanger 612 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooling intermediate pressure gas stream 614 can then be compressed in the second compressor 616 to form a high pressure gas stream 618. The pressure of the high pressure gas stream 618 can be higher than 2,000 psia (13,790 kPa) or more preferably higher than 3,000 psia (20,680 kPa). The high-pressure gas stream 618 can flow through a second heat exchanger 620 that is cooled by the high-pressure gas stream 618 indirectly exchanging heat with the environment to form a cooling high-pressure gas stream 622. The second heat exchanger 620 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooling high pressure gas stream 622 can then form a pretreated gas stream 626 that has been expanded and cooled in the HPCE inflator 624. The pressure of the cold pretreatment gas stream 626 is less than 3,000 psia (20,680 kPa) or more preferably less than 2,000 psia (13,790 kPa), where the pressure of the cold pretreatment gas stream 626 is cooling. It is less than the pressure of the high pressure gas stream 622. In aspects, the second compressor 616 can be driven exclusively by the shaft power generated by the inflator 624, as represented by the dashed line 628.

As shown in FIG. 6, the chilled pretreatment gas stream 626 is directed away from HPCE step 601 to feed gas expander based step 600. The cold pretreatment gas stream 626 can be separated into a second cold pretreatment gas stream 630, a first refrigerant stream 632, and a second refrigerant stream 634. The first refrigerant stream 632 can be expanded in the first inflator 636 to produce the first cooling stream 638. The first cooling stream 638 enters at least one cold heat exchanger 640, which cools this stream by exchanging heat with the second cold pretreatment gas stream 630 and the second refrigerant stream 634. The first cooling stream 638 exits at least one cold heat exchanger 640 as the first warm stream 642. The second refrigerant stream 634 can be cooled by at least one cold heat exchanger 640 and then expanded by the second expander 644 to produce a two-phase stream 646. The pressure of the two-phase stream 646 can be the same as or lower than the pressure of the first cooling stream 638. The two-phase stream 646 is separated into its vapor component and its liquid component in the first two-phase separator 648 to form a second cooling stream 650 and a second pressurized LNG stream 652. The temperature of the first cooling stream 638 is higher than the temperature of the second cooling stream 650. The second cooling stream 650 enters at least one cold heat exchanger 640, which cools this stream by exchanging heat with the second cold pretreatment gas stream 630 and the second refrigerant stream 634. The second cooling stream 650 exits at least one heat exchanger 640 as a second warm stream 654. The second cold pretreated natural gas stream 630 exchanges heat with the first cooling stream 638 and the second cooling stream 650 to produce a first pressurized LNG stream 656. The first pressurized LNG stream 656 can reduce the pressure in the hydraulic turbine 658 after leaving at least one heat exchanger 640. The first pressurized LNG stream 656 can be mixed with the second pressurized LNG stream 652 to form a composite pressurized LNG stream 660. The combined pressurized LNG stream 660 can be directed to a second two-phase separator 662 where the pressure of the combined pressurized LNG stream 660 drops, while the resulting two-phase stream is the end flush gas stream 664 and the product LNG stream. Separated into 667. The end flush gas stream 644 can heat exchange with the first pressurized LNG stream 656 in the end flush gas heat exchanger 668 before directing the first pressurized LNG stream 656 to the hydraulic turbine 658. Further, the end flush gas stream 664 can enter at least one cold heat exchanger 640 and exchange heat with the second cold pretreatment gas stream 630 and the second refrigerant stream 634 to cool the above stream. can. The end flush gas stream 664 exits at least one heat exchanger 640 as a third warm stream 670. The third warm stream 670 can be compressed by the first recirculation gas compressor 672 and is heat exchanged with the environment in the first recirculation heat exchanger 674 to form the first recirculation gas stream 676. Can be formed. The first recirculated gas stream 676 can be combined with the second warm stream 654 and simultaneously compressed in the second recirculated gas compressor 678 and the second recirculated heat exchanger 680. It can exchange heat with the environment within to form a second recirculated gas stream 682. The second recirculated gas stream 682 can be combined with the first warm stream 642 and simultaneously compressed in the third and fourth recirculated gas compressors 684, 686, and the third recirculated gas stream 682. The recirculated refrigerant gas stream 604 can be formed by exchanging heat with the environment in the circulating heat exchanger 688. The third recirculating gas compressor 684 can be driven exclusively by the shaft power generated by the first inflator 636, as indicated by the dashed line 690. The fourth recirculating gas compressor 686 can be driven exclusively by the shaft power generated by the second inflator 644, as shown by the dashed line 692.

FIG. 7 shows a method 700 for producing LNG according to the disclosed embodiment. At block 702, the natural gas stream can be supplied from a natural gas supply. At block 704, the natural gas stream can be compressed to a pressure of at least 2,000 psia in at least two series-arranged compressors to form a compressed natural gas stream. At block 706, the compressed natural gas stream is cooled and can form a cooled compressed natural gas stream. At block 708, the cooled compressed natural gas stream has a pressure of less than 3,000 psia in at least one work-producing natural gas expander and no higher than the pressure at which at least two series-arranged compressors compress the natural gas stream. Inflated to, thereby forming a chilled natural gas stream. At block 710, the cold natural gas stream can be liquefied.

FIG. 8 is a diagram illustrating another HPCE step 800 according to the disclosed embodiment. As in the HPCE step 100 shown in FIG. 1, the HPCE step 800 can include a first compressor 802 that compresses the pretreated natural gas stream 804 to form an intermediate pressure gas stream 806. The intermediate pressure gas stream 806 can flow through a first heat exchanger 808 that is cooled by the intermediate pressure gas stream 806 indirectly exchanging heat with the environment to form a cooling intermediate pressure gas stream 810. The first heat exchanger 808 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooling intermediate pressure gas stream 810 can then be compressed in the second compressor 812 to form the high pressure gas stream 814. The pressure of the high pressure gas stream 814 can be higher than 2,000 psia (13,790 kPa) or more preferably higher than 3,000 psia (20,680 kPa). The high pressure gas stream 814 can flow through a second heat exchanger 816 that is cooled by the high pressure gas stream 814 indirectly exchanging heat with the environment to form a cooling high pressure gas stream 818. The second heat exchanger 816 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooling high pressure gas stream 818 can then be directed to the high pressure heat exchanger 826, where it has an ambient temperature by exchanging heat with one or more refrigerant streams 828 from an external process of HPCE process 800. Further cooled to a lower temperature. In one aspect, the one or more refrigerant streams are refrigerant streams that have cooled, cooled, and / or liquefied the cooled pretreated natural gas stream 822 after it has exited HPCE step 800. These refrigerant streams can still be cold enough to cool the cooling high pressure gas stream 818, even after liquefying the natural gas. The cooling high pressure gas stream 818 exits the high pressure heat exchanger 826 at a temperature below 30 ° C, below 20 ° C or below 15 ° C, and is expanded and cooled in the expander 820. Form a gas stream 822. The pressure of the cold pretreatment gas stream 122 can be less than 3,000 psia (20,680 kPa) or more preferably less than 2,000 psia (13,790 kPa), and the pressure of the cold pretreatment gas stream 822 is It is less than the pressure of the cooling high pressure gas stream 818. In a preferred embodiment, the second compressor 812 can be driven exclusively by the shaft power generated by the inflator 820, as shown by the dashed line 824.

FIG. 9 shows the implementation of the HPCE step 901, which is similar to the HPCE step 601 and is combined with the feed gas expander-based LNG liquefaction step 900. These elements of FIG. 9, identified by the reference numbers found in FIG. 6 (eg, 636, 644, 668), perform the same or similar functions as the elements described above and are not described further for the sake of brevity. It will be. The HPCE step 901 includes a high pressure heat exchanger 905 that exchanges heat between a cooling high pressure gas stream 622 and a first warm stream 642 exiting at least one low temperature heat exchanger 640. After passing through the high pressure heat exchanger 905, the first warm stream 642 is combined with the second recirculated gas stream 682 as described above in the third and fourth recirculated gas compressors 684, 686. It is compressed.

FIG. 10 shows another implementation of HPCE step 1001, which is similar to HPCE step 601 and is combined with feed gas expander-based LNG liquefaction step 1000. These elements of FIG. 10, identified by the reference numbers found in FIG. 6 (eg, 636, 644, 668), perform the same or similar functions as the elements described above and are not described further for the sake of brevity. It will be. The HPCE step 1001 includes a high pressure heat exchanger 1005 that exchanges heat between a cooling high pressure gas stream 622 and a second warm stream 654 exiting at least one low temperature heat exchanger 640. After passing through the high pressure heat exchanger 1005, the second warm stream 654 is combined with the first recirculated gas stream 676 as described above and compressed in the second recirculated gas compressor 678.

FIG. 11 shows another implementation of HPCE step 1101, which is similar to HPCE step 601 and is combined with feed gas expander based LNG liquefaction step 1100. These elements of FIG. 11, identified by the reference numbers found in FIG. 6 (eg, 636, 644, 668), perform the same or similar functions as the elements described above and are not described further for the sake of brevity. It will be. The HPCE step 1101 includes a high pressure heat exchanger 1105 that exchanges heat between a cooling high pressure gas stream 622 and a first warm stream 642 and a second warm stream 654 exiting at least one low temperature heat exchanger 640. After passing through the high pressure heat exchanger 1105, the first warm stream 642 is combined with the second recirculated gas stream 682 as described above in the third and fourth recirculated gas compressors 684, 686. It is compressed. After passing through the high pressure heat exchanger 1105, the second warm stream 654 is combined with the first recirculated gas stream 676 as described above and compressed in the second recirculated gas compressor 678.

The disclosed embodiment comprising a high pressure heat exchanger in the HPCE module (ie, FIGS. 8-11) is still cold enough to utilize the refrigerant stream and increase the precooling of the natural gas stream of the HPCE module after initial use. The advantage of using such a high pressure heat exchanger in the HPCE module is that the efficiency of the entire liquefaction process shown in FIG. 9 can be improved by about 3% compared to, for example, the efficiency of the liquefaction process shown in FIG. Is.

FIG. 12 is a method 1200 for producing LNG according to the disclosed embodiment. At block 1202, the natural gas stream can be supplied from a natural gas supply. At block 1204, the natural gas stream can be compressed to a pressure of at least 2,000 psia in at least two series-arranged compressors to form a compressed natural gas stream. At block 1206, the compressed natural gas stream is cooled and can form a cooled compressed natural gas stream. At block 1208, the cooled compressed natural gas stream is additionally cooled to a temperature below the ambient temperature to form an additional cooled compressed natural gas stream. At block 1210, the cooled compressed natural gas stream has a pressure of less than 3,000 psia in at least one work-producing natural gas expander and no higher than the pressure at which at least two series-arranged compressors compress the natural gas stream. Inflated to, thereby forming a chilled natural gas stream. At block 1212, the cold natural gas stream can be liquefied.

The disclosed embodiments may include any combination of methods and systems shown in the numbered paragraphs below. This is not considered to be a complete list of all possible embodiments, as any number of variants can be envisioned from the above description.
1. 1. Cooling compression, the step of feeding the natural gas stream from the natural gas supply, and the step of compressing the natural gas stream with at least two series-arranged compressors up to a pressure of at least 2,000 psia to form the compressed natural gas stream. Ambient temperature to form a natural gas stream Compressed to cool the natural gas stream by indirect heat exchange with air or water Compressed to a temperature lower than the ambient temperature to form an additional cooling compressed natural gas stream Compressed natural Additional cooling of the gas stream and at least one job generation of additional cooling compressed natural gas stream to a pressure less than 3,000 psia and not higher than the pressure at which at least two series-arranged compressors compress the natural gas stream. The stage of expanding in a natural gas inflator to form a cooled natural gas stream, and the stage of liquefying the cooled natural gas stream by indirect heat exchange with the refrigerant to form liquefied natural gas and warm refrigerant. A method in which a cooled compressed natural gas stream comprises liquefied natural gas (LNG) that is additionally cooled using warm refrigerants.
2. 2. The method of paragraph 1 in which the step of liquefying a cold natural gas stream is carried out within one or more single mixed refrigerant (SMR) liquefaction trains.
3. 3. The step of liquefying the cold natural gas stream takes place in one or more expander-based liquefaction modules, with the expander-based liquefaction module being the nitrogen gas expander-based liquefaction module and the feed gas expander-based. The method of paragraph 1 which is one of the liquefaction modules of.
4. The feed gas inflator-based liquefaction module is an open-loop feed gas inflator-based liquefaction module, and the recirculated refrigerant stream in the open-loop feed gas inflator-based process is a natural gas stream before the compression phase. The method of paragraph 3 combined with.
5. The chilled natural gas stream is the first chilled natural gas stream, and the method is to transform the first chilled natural gas stream into a second chilled natural gas stream, a first refrigerant stream, and a second refrigerant. It has a second temperature, a step of separating into streams, a step of discharging a first cooling stream having a first temperature from a warm-end inflator forming part of a feed gas inflator-based liquefaction module. Paragraph 4 in which the first temperature is higher than the second temperature, further comprising discharging the second cooling stream from the cold end expander forming part of the feed gas expander-based liquefaction module. Method.
6. A step of expanding the first refrigerant stream in the warm end expander to generate the first cooling stream and a step of expanding the second refrigerant stream in the cold end expander to generate the second cooling stream. The method of step 5 further comprising.
7. A step of discharging a first cooling stream having a first temperature from a warm-end inflator forming part of a feed gas inflator-based liquefaction module and a feed gas of a two-phase stream having a second temperature. Discharge from the cold-end inflator, which forms part of the inflator-based liquefaction module, and expand the first refrigerant stream in the warm-end inflator as well as when the first temperature is higher than the second temperature. The stage of generating the first cooling stream, the stage of expanding the second refrigerant stream in the cold end expander to generate the two-phase stream, and the stage of combining the two-phase stream with the second cooling stream and the first pressurization. The method of paragraph 4 further comprising the step of separating into an LNG stream.
8. The method of any of paragraphs 5-7, wherein the pressure of the first cooling stream is either the same as or similar to the pressure of the second cooling stream or higher than the pressure of the second cooling stream.
9. The liquefaction stage cools the second cold natural gas stream by exchanging heat with the first and second cooling streams to form the first warm cooling stream and the second warm cooling stream. The method of any of paragraphs 5-7, comprising the step of forming a second pressurized LNG stream.
10. The method of paragraph 9, wherein the second pressurized LNG stream is mixed with the first pressurized LNG stream before inflating the second pressurized LNG stream.
11. A step of reducing the pressure of the second pressurized LNG stream and a second pressurized LNG stream of depressurization are referred to as an end flush gas stream so that the second pressurized LNG stream undergoes at least one stage of pressure drop. The method of paragraph 9, further comprising a step of separating into an LNG stream and a step of cooling a second pressurized LNG stream and a second cold natural gas stream using an end flush gas stream.
12. After cooling the second pressurized LNG stream and the second cold natural gas stream using the end flush gas stream, the end flash gas stream is compressed and the compressed end flash gas stream is re-released by one or more. The method of paragraph 11 further comprising mixing with a circulating refrigerant stream.
13. After cooling the second pressurized LNG stream and the second cold natural gas stream using the end flush gas stream, the steps of compressing the end flash gas stream and using the compressed end flush gas stream as fuel. Further including the method of paragraph 11.
14. The method of paragraph 9 where the first warm cooling stream is used as the warm refrigerant and the cooling compressed natural gas stream is additionally cooled to form an additional cooling compressed natural gas stream.
15. The method of paragraph 9 where a second warm cooling stream is used as the warm refrigerant and the cooling compressed natural gas stream is additionally cooled to form an additional cooling compressed natural gas stream.
16. The method of paragraph 3 wherein the expander-based liquefaction module comprises a first expansion refrigerant in a first gas phase refrigeration circuit and a second expansion refrigerant in a second gas phase refrigeration circuit.
17. The method of paragraph 16 where the first expanding refrigerant is the feed gas.
18. The method of paragraph 16 or paragraph 17, wherein the first gas phase refrigeration circuit is a closed loop refrigeration circuit.
19. The method of any of paragraphs 16-18, wherein the second expanding refrigerant is nitrogen.
20. The method of any of paragraphs 16-19, wherein the second gas phase refrigeration circuit is a closed loop refrigeration circuit.
21. The method of any of paragraphs 1-20, wherein at least two compressors compress the natural gas stream to a pressure higher than 3,000 psia.
22. The method of any of paragraphs 1-21, wherein the natural gas inflator is a work-generated inflator that inflates an additional cooled compressed natural gas stream to a pressure of less than 2,000 psia.
23. The method of any of paragraphs 1-22, further comprising the steps of performing compression, cooling, additional cooling, expansion, and liquefaction on the upper deck of the floating LNG structure.
24. The method of any of paragraphs 1-23, wherein the temperature of the additional cooling compressed natural gas stream is less than 30 ° C.
25. The method of any of paragraphs 1-24, wherein the temperature of the additional cooling compressed natural gas stream is less than 15 ° C.
26. A device for liquefaction of natural gas, at least two series-arranged compressions configured to compress a natural gas stream to a pressure higher than 2,000 psia, thereby forming a compressed natural gas stream. The vessel, the cooling elements configured to cool the compressed natural gas stream and thereby form the cooled compressed natural gas stream, and the cooled compressed natural gas stream further cooled to a temperature below the ambient temperature, thereby adding. A heat exchanger configured to produce a cooled compressed natural gas stream and an additional cooled compressed natural gas stream less than 3,000 psia and at least two series-arranged compressors above the pressure to compress the natural gas stream. It includes at least one work-generating inflator configured to expand to a moderate pressure, thereby forming a chilled natural gas stream, and a liquefaction train configured to liquefy the chilled natural gas stream. A device in which the warm refrigerant used by the liquefaction train is directed to the heat exchanger to further cool the cooled compressed natural gas stream.
27. When the liquefaction train includes one of a nitrogen gas inflator-based liquefaction module and an open-loop feed gas inflator-based liquefaction module and the device includes an open-loop feed gas inflator-based module in the liquefaction train. Further includes a recirculated refrigerant stream of an open-loop feed gas expander-based module combined with the natural gas stream before the natural gas stream is compressed by two or more series-arranged compressors and cooled. The device of paragraph 26, wherein the natural gas stream is a first cold natural gas stream separated into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.
28. A warm-end inflator configured such that a feed gas inflator-based liquefaction module expands a first refrigerant stream to form a first cooling stream with a first temperature discharged from it. A second cooling stream having a second temperature and a cold end expander configured to form one of a two-phase stream that expands the second refrigerant stream and is discharged from it. The device of paragraph 27, wherein the temperature of 1 is higher than the temperature of the second.
29. The device of any of paragraphs 26-28, wherein the natural gas inflator is a work-generated inflator configured to inflate a cooled compressed natural gas stream to a pressure of less than 2,000 psia.
30. The device of any of paragraphs 26-29, wherein at least two series-arranged compressors, cooling elements, heat exchangers, at least one work-generating inflator, and a liquefaction train are arranged on a floating LNG structure. ..
31. The device of paragraph 30 in which at least two series-arranged compressors, cooling elements, heat exchangers, and at least one work-generating inflator are arranged in a single module on the upper deck of a floating LNG structure. ..
32. A floating LNG structure with at least two series-arranged compressors configured to compress the natural gas stream to a pressure above 2,000 psia, thereby forming a compressed natural gas stream. Cooling elements configured to cool the compressed natural gas stream, thereby forming a cooled compressed natural gas stream, and further cooling the compressed natural gas stream to a temperature below the ambient temperature, thereby additional cooling compressed natural. Pressure not higher than the pressure at which a heat exchanger configured to produce a gas stream and an additional cooling compressed natural gas stream less than 3,000 psia and at least two series-arranged compressors compress the natural gas stream. Includes at least one work-generating inflator configured to expand to and thereby form a chilled natural gas stream, and a liquefaction train configured to liquefy the chilled natural gas stream by liquefaction train. A floating LNG structure in which the warm refrigerant used is directed to the heat exchanger to further cool the cooled compressed natural gas stream.

Although the above relates to the aspects disclosed by the present invention, other and yet other aspects of the disclosure of the present invention can be devised without departing from the basic scope, and the scope thereof is as follows. Determined by the scope of claims.

800: HPCE process 802: First compressor 806: Intermediate pressure gas stream 816: Second heat exchanger 828: Refrigerant stream

Claims (15)

A method of producing liquefied natural gas (LNG).
The stage of supplying a natural gas stream from a natural gas supply,
A step of compressing the natural gas stream to a pressure of at least 2,000 psia in at least two series-arranged compressors to form a compressed natural gas stream.
A step of cooling the compressed natural gas stream by indirect heat exchange with ambient temperature air or water to form a cooled compressed natural gas stream.
A step of additionally cooling the cooled compressed natural gas stream to a temperature lower than the ambient temperature to form an additional cooled compressed natural gas stream.
At least one work-generated natural gas expansion to a pressure of less than 3,000 psia of the additional cooling compressed natural gas stream and not higher than the pressure at which the at least two series-arranged compressors compress the natural gas stream. The stage of inflating in the vessel, thereby forming a cooled natural gas stream,
It comprises the steps of liquefying the cold natural gas stream by indirect heat exchange with the refrigerant to form liquefied natural gas and a warm refrigerant.
The cooled compressed natural gas stream is additionally cooled using the warm refrigerant.
The step of liquefying the cold natural gas stream is performed in one or more inflator-based liquefaction modules.
The inflator-based liquefaction module is a feed gas inflator-based liquefaction module .
The chilled natural gas stream is the first chilled natural gas stream.
The above method
A step of separating the first cold natural gas stream into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.
A step of discharging a first cooling stream having a first temperature from a warm-end inflator forming part of the feed gas inflator-based liquefaction module.
Further comprising ejecting a second cooling stream having a second temperature from the cold end expander forming part of the feed gas inflator based liquefaction module.
The first temperature is higher than the second temperature.
A method characterized by that. The feed gas inflator-based liquefaction module is an open-loop feed gas inflator-based liquefaction module.
The recirculated refrigerant stream in the open-loop feed gas expander-based process is combined with the natural gas stream prior to the compression step.
The method according to claim 1, wherein the method is characterized by the above. A step of expanding the first refrigerant stream in the warm-end inflator to generate the first cooling stream.
Further comprising the step of expanding the second refrigerant stream in the cold end expander to generate the second cooling stream.
The method according to claim 1 or 2 , wherein the method is characterized by the above. The pressure of the first cooling stream is
Same as or higher than the pressure of the second cooling stream.
One of them,
The method according to any one of claims 1 to 3 , wherein the method is characterized by the above. The liquefaction step was cooled by exchanging heat with the first cooling stream and the second cooling stream to form a first warm cooling stream and a second warm cooling stream. Including the step of cooling the natural gas stream to form a second pressurized LNG stream,
The method according to any one of claims 1 to 3 , wherein the method is characterized by the above. The second pressurized LNG stream is mixed with the first pressurized LNG stream before expanding the second pressurized LNG stream.
The method according to claim 5 , wherein the method is characterized by the above. A step of reducing the pressure of the second pressurized LNG stream so that the second pressurized LNG stream receives at least one stage of pressure reduction.
The step of separating the depressurized second pressurized LNG stream into an end flush gas stream and an LNG stream, and
Further comprising cooling the second pressurized LNG stream and the second chilled natural gas stream using the end flush gas stream.
The method according to claim 5 , wherein the method is characterized by the above. After cooling the second pressurized LNG stream and the second cold natural gas stream using the end flush gas stream, the end flash gas stream is compressed and the compressed end flush gas stream is 1 Or at the stage of mixing with two or more recirculated refrigerant streams, or
Further comprising the step of using the compressed end flush gas stream as fuel.
The method according to claim 7 , wherein the method is characterized by the above. The first warm cooling stream or the second warm cooling stream is used as the warm refrigerant to additionally cool the cooled compressed natural gas stream to form the additional cooled compressed natural gas stream.
The method according to claim 5 , wherein the method is characterized by the above. The natural gas inflator is a work-generated inflator that inflates the additional cooled compressed natural gas stream to a pressure of less than 2,000 psia.
The method according to any one of claims 1 to 9 , wherein the method is characterized by the above. Further including a step of performing the compression step, a cooling step, an additional cooling step, an expansion step, and a liquefaction step on the upper deck of the floating LNG structure.
The method according to any one of claims 1 to 10 , wherein the method is characterized by the above. The temperature of the additional cooling compressed natural gas stream is less than 30 ° C or less than 15 ° C.
The method according to any one of claims 1 to 11 , wherein the method is characterized by that. A device for liquefaction of natural gas
With at least two series-arranged compressors configured to compress the natural gas stream to a pressure higher than 2,000 psia, thereby forming a compressed natural gas stream.
A cooling element configured to cool the compressed natural gas stream and thereby form a cooled compressed natural gas stream.
A heat exchanger configured to further cool the cooled compressed natural gas stream to a temperature below the ambient temperature, thereby producing an additional cooled compressed natural gas stream.
The additional cooled compressed natural gas stream is expanded to a pressure less than 3,000 psia and not higher than the pressure at which the at least two series-arranged compressors compress the natural gas stream, thereby cooling the natural gas stream. With at least one work-generating inflator configured to form a gas stream,
With a liquefaction train configured to liquefy the cold natural gas stream,
The liquefaction train comprises an open- loop feed gas expander-based liquefaction module .
The warm refrigerant used by the liquefaction train is directed at the heat exchanger to further cool the cooled compressed natural gas stream.
The chilled natural gas stream is the first chilled natural gas stream.
The first cold natural gas stream is separated into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.
The feed gas inflator-based liquefaction module comprises a warm-end inflator, which expands the first refrigerant stream and releases a first cooling stream from the warm-end inflator. The first cooling stream has a first temperature and is configured to produce.
The feed gas inflator-based liquefaction module comprises a cold-end inflator, which expands the second refrigerant stream and releases a second cooling from the cold-end inflator. The second cooling stream or the two-phase stream is configured to generate one of a stream and a two-phase stream and has a second temperature.
The first temperature is higher than the second temperature.
A device characterized by that. The at least two series-arranged compressors, the cooling element, the heat exchanger, the at least one work-generating inflator, and the liquefaction train are arranged or arranged on a floating LNG structure.
Placed on a single module on the upper deck of the floating LNG structure,
13. The apparatus according to claim 13 . It is a floating LNG structure and
With at least two series-arranged compressors configured to compress the natural gas stream to a pressure higher than 2,000 psia, thereby forming a compressed natural gas stream.
A cooling element configured to cool the compressed natural gas stream and thereby form a cooled compressed natural gas stream.
A heat exchanger configured to further cool the cooled compressed natural gas stream to a temperature below the ambient temperature, thereby producing an additional cooled compressed natural gas stream.
The additional cooled compressed natural gas stream is expanded to a pressure less than 3,000 psia and not higher than the pressure at which the at least two series-arranged compressors compress the natural gas stream, thereby cooling the natural gas stream. With at least one work-generating inflator configured to form a gas stream,
With a liquefaction train configured to liquefy the cold natural gas stream,
The liquefaction train comprises one of a nitrogen gas expander-based liquefaction module and an open-loop feed gas expander-based liquefaction module.
The warm refrigerant used by the liquefaction train is directed at the heat exchanger to further cool the cooled compressed natural gas stream.
The chilled natural gas stream is the first chilled natural gas stream.
The first cold natural gas stream is separated into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.
The feed gas inflator-based liquefaction module comprises a warm-end inflator, which expands the first refrigerant stream and releases a first cooling stream from the warm-end inflator. The first cooling stream has a first temperature and is configured to produce.
The feed gas inflator-based liquefaction module comprises a cold-end inflator, which expands the second refrigerant stream and releases a second cooling from the cold-end inflator. The second cooling stream or the two-phase stream is configured to generate one of a stream and a two-phase stream and has a second temperature.
The first temperature is higher than the second temperature.
A floating LNG structure characterized by this.

Images